Reciprocating Pump Piston Control

ABSTRACT

A sampling tool for conveyance within a well that extends into a subterranean formation. The sampling tool includes a displacement unit having a first cylinder, a second cylinder, a piston, and a magnet. The piston includes a first head located within the first cylinder and a second head located within the second cylinder. A stroke of the piston moves the first and second heads between first positions, in which each of the first and second heads are proximate first end walls of the respective first and second cylinders, and second positions, in which each of the first and second heads are proximate second end walls of the respective first and second cylinders. The magnet is carried with one or more of the first and second heads. The sampling tool further includes a magnetic field sensor operable to measure a magnetic field strength the magnet throughout the stroke.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a Continuation-In-Part (CIP) of U.S. patent application Ser. No. 14/577,844, titled “PUMP OPERATION PROCEDURE WITH PISTON POSITION SENSOR,” filed Dec. 19, 2014, Attorney Docket No. IS13.4430, the entire disclosure of which is hereby incorporated herein by reference.

BACKGROUND OF THE DISCLOSURE

Wells are generally drilled into subsurface rocks to access fluids, such as hydrocarbons, stored in subterranean formations. The formations penetrated by a well may be evaluated for various purposes, including for identifying hydrocarbon reservoirs within the formations. During drilling operations, one or more drilling tools in a drill string may be utilized to test or sample the formations. Following removal of the drill string, a wireline tool may also be run into the well to test or sample the formations. These drilling tools and wireline tools, as well as other wellbore tools conveyed on coiled tubing, drill pipe, casing, or other means of conveyance, are also referred to herein as “downhole tools.” Certain downhole tools may include two or more integrated collar assemblies, each for performing a separate function. Certain downhole tools may be employed alone or in combination with other downhole tools in a downhole tool string.

Formation evaluation may involve drawing fluid from the formation into a downhole tool. In some instances, the fluid drawn from the formation is retained within the downhole tool for later testing outside of the well. In other instances, downhole fluid analysis may be utilized to test the fluid while the downhole tool remains in the well. Such analysis may be utilized to provide information on certain fluid properties in real time without a delay associated with returning the fluid samples to the surface.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces an apparatus that includes a sampling tool for conveyance within a well that extends into a subterranean formation. The sampling tool includes a displacement unit that includes a first cylinder, a second cylinder, and a piston having a first head disposed in the first cylinder and a second head disposed in the second cylinder. A stroke of the piston moves the first and second heads between first positions each proximate first end walls of the respective first and second cylinders and second positions each proximate second end walls of the respective first and second cylinders. The displacement unit also includes a first magnet carried with the first head and a second magnet carried with the second head. The sampling tool also includes a single magnetic field sensor operable to measure a first magnetic field strength of the first magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke. The single magnetic field sensor is also operable to measure a second magnetic field strength of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke.

The present disclosure also introduces an apparatus that includes a sampling tool for conveyance within a well that extends into a subterranean formation, the sampling tool including a displacement unit having a first cylinder, a second cylinder, and a piston including a first head disposed in the first cylinder and a second head disposed in the second cylinder. A stroke of the piston moves the first and second heads between first positions each proximate first end walls of the respective first and second cylinders and second positions each proximate second end walls of the respective first and second cylinders. The sampling tool also includes at least one magnet carried with at least one of the first and second heads, and at least one magnetic field sensor operable to measure a magnetic field strength of the at least one magnet throughout the stroke.

The present disclosure also introduces a method that includes conveying a sampling tool within a well that extends into a subterranean formation. The sampling tool includes a hydraulically actuated displacement unit having a piston and first and second magnets carried with and disposed proximate opposing ends of the piston. The sampling tool also includes a magnetic field sensor operable to substantially continuously generate: first information related to a first magnetic field of the first magnet as the piston moves through a first portion of a stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and second information related to a second magnetic field of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke. The method also includes operating the sampling tool to draw formation fluid from the subterranean formation into the displacement unit. Operating the sampling tool causes movement of the piston within the displacement unit to be controlled based on at least the first and second information.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic view of at least a portion of another example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 3 is a schematic view of a portion of an example implementation of the apparatus shown in FIGS. 1 and 2 according to one or more aspects of the present disclosure.

FIG. 4 is another schematic view of a portion of an example implementation of the apparatus shown in FIGS. 1 and 2 according to one or more aspects of the present disclosure.

FIG. 5 is a flow-chart diagram of at least a portion of a method according to one or more aspects of the present disclosure.

FIGS. 6-8 are graphs related to one or more aspects of the present disclosure.

FIG. 9 is another flow-chart diagram of at least a portion of a method according to one or more aspects of the present disclosure.

FIG. 10 is another flow-chart diagram of at least a portion of a method according to one or more aspects of the present disclosure.

FIG. 11 is a schematic view of a portion of an example implementation of the apparatus shown in FIG. 3 according to one or more aspects of the present disclosure.

FIG. 12 is a schematic view of another example implementation of the apparatus shown in FIG. 11 according to one or more aspects of the present disclosure.

FIG. 13 is a schematic view of another example implementation of the apparatus shown in FIG. 11 according to one or more aspects of the present disclosure.

FIGS. 14-17 are graphs related to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various implementations and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include implementations in which the first and second features are formed in direct contact, and may also include implementations in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

The systems and methods of the present disclosure may be used or performed in connection with formation evaluation while drilling processes. The phrase “formation evaluation while drilling” refers to various sampling and testing operations that may be performed during the drilling process, such as sample collection, fluid pump out, pretests, pressure tests, fluid analysis, and resistivity tests, among others. It will be understood that the measurements made during “formation evaluation while drilling” may be made while a drill bit is not actually cutting through a formation. For example, sample collection and pump out may be performed during brief stops in the drilling process. That is, the rotation of the drill bit is briefly stopped so that the measurements may be made. Drilling may continue once the measurements are made. Even in implementations where measurements are made after drilling is stopped, the measurements may still be made without having to trip the drill string.

In this disclosure, “hydraulically coupled” or “hydraulically connected” and similar terms may be used to describe bodies that are connected in such a way that fluid pressure may be transmitted between and among the connected items. The term “in fluid communication” is used to describe bodies that are connected in such a way that fluid may flow between and among the connected items. It is noted that hydraulically coupled or connected may include certain arrangements where fluid may not flow between the items, but the fluid pressure may still be transmitted. Thus, fluid communication is a subset of hydraulically coupled.

FIG. 1 is a schematic view of at least a portion of an example implementation of a wellsite system 10 according to one or more aspects of the present disclosure. While certain elements of the wellsite system 10 are depicted in this figure and generally discussed below, it is to be understood that the wellsite system 10 may include other components in addition to, or in place of, those presently illustrated and discussed. As depicted, the wellsite system 10 includes a sampling tool 12 suspended by a cable 16 within a wellbore 14 extending through a subterranean formation 15. The cable 16 may be a wireline cable that may support the sampling tool 12 and may include at least one conductor that facilitates data communication between the sampling tool 12 and a control and monitoring system 18 disposed on the surface. However, it is to be understood that the sampling tool 12 may be conveyed within the wellbore 14 via other conveyance means, such as wired drill pipe or coiled tubing, among others.

The cable 16, and hence the sampling tool 12, may be positioned within the wellbore 14 in a suitable manner. As an example, the cable 16 may be connected to a drum (not shown), permitting rotation of the drum to raise and lower the sampling tool 12. The drum may be disposed on a service truck or a stationary platform. The service truck or stationary platform may further contain the control and monitoring system 18. The control and monitoring system 18 may include one or more computer systems or devices and/or may be a distributed computer system. For example, collected data or information may be stored, distributed, communicated to an operator, and/or processed locally or remotely. The control and monitoring system 18 may, individually or in combination with other system components, perform the methods discussed below, or portions thereof.

The sampling tool 12 may include multiple components. For example, the illustrated sampling tool 12 includes a probe module 20, a fluid analysis module 22, a pump-out module 24, a power module 26, and a fluid sampling module 28. However, in further implementations, the sampling tool 12 may include additional or fewer components.

The probe module 20 of the sampling tool 12 includes one or more inlets 30 that may engage or be positioned adjacent to a wall 34 of the wellbore 14 to receive therein formation fluid and/or other fluid located within the formation and/or the wellbore 14. The fluid received into the sampling tool 12 through the one or more inlets 30 is collectively referred to hereinafter as a “downhole fluid.” The one or more inlets 30 may be designed to provide focused or un-focused fluid sampling. Furthermore, the probe module 20 may further include one or more deployable members 32 configured to place the inlets 30 into engagement with the wall 34 of the wellbore 14. For example, the deployable member 32 includes an inflatable packer that may be expanded circumferentially around the probe module 20 to extend the inlets 30 into engagement with the wall 34. In another implementation, the one or more deployable members 32 may be one or more setting pistons that may be extended against one or more points on the wall 34 of the wellbore 14 to urge the inlets 30 against the wall 34. In yet another implementation, the inlets 30 may be disposed on one or more extendable probes designed to engage the wall 34.

The pump-out module 24 includes a pump assembly 25 that draws the downhole fluid through a flow line 36 extending within the sampling tool 12. In the illustrated implementation, the flow line 36 provides fluid communication between the one or more inlets 30 and an outlet 38. As shown in FIG. 1, the flow line 36 extends from the probe module 20 and through the fluid analysis module 22 before reaching the pump-out module 24. However, in other implementations, the arrangement of the modules 20, 22, and 24 may vary. For example, in certain implementations, the fluid analysis module 22 may be disposed on the other side of the pump-out module 24. As further shown in FIG. 1, the flow line 36 may also extend through the power module 26 and the fluid sampling module 28 before reaching the outlet 38.

The fluid sampling module 28 may selectively retain some downhole fluid for transport to the surface for further evaluation outside the wellbore 14. In some implementations, the fluid analysis module 22 may include a fluid analyzer 23 that may be employed to provide in situ downhole fluid evaluations. For example, the fluid analyzer 23 may include a spectrometer and/or a gas analyzer designed to measure properties, such as, optical density, fluid density, fluid viscosity, fluid fluorescence, fluid composition, and fluid gas-oil ratio, among others. According to certain implementations, the spectrometer may include a suitable number of measurement channels for detecting different wavelengths, and may include a filter-array spectrometer or a grating spectrometer. For example, the spectrometer may be a filter-array absorption spectrometer having ten measurement channels. In other implementations, the spectrometer may have sixteen channels or twenty channels, and may be provided as a filter-array spectrometer or a grating spectrometer, or a combination thereof (e.g., a dual spectrometer). According to certain implementations, the gas analyzer may include one or more photodetector arrays that detect reflected light rays at certain angles of incidence. The gas analyzer may also include a light source, such as a light emitting diode, a prism, such as a sapphire prism, and a polarizer, among other components. In certain implementations, the gas analyzer may include a gas detector and one or more fluorescence detectors operable to detect free gas bubbles and retrograde condensate liquid drop out.

One or more additional measurement devices, such as temperature sensors, pressure sensors, viscosity sensors, chemical sensors (e.g., for measuring pH or H2S levels), and gas chromatographs, may also be included within the fluid analyzer 23. Further, the fluid analyzer 23 may include a resistivity sensor and/or a density sensor, which, for example, may be a densimeter or a densitometer. In certain implementations, the fluid analysis module 22 may include a controller (not shown), such as a microprocessor or control circuitry designed to calculate certain fluid properties based on the sensor measurements. Further, in certain implementations, the controller may govern sampling operations based on the downhole fluid measurements or properties. Moreover, in other implementations, the controller may be disposed within or constitute another module of the sampling tool 12. For example, the fluid sampling tool 12 may include a downhole controller 40 that may include one or more computer systems or devices and/or may be part of a distributed computer system. The downhole controller 40 may, individually or in combination with other system components (e.g., control and monitoring system 18), perform the methods discussed below, or portions thereof.

While FIG. 1 illustrates the sampling operations being conducted with a wireline system, it is to be understood that other implementations are contemplated. FIG. 2 is a schematic view of at least a portion of an example implementation of a wellsite system 42 illustrating the sampling operations being conducted with a drilling system according to one or more aspects of the present disclosure. The wellsite system 42 comprises a wellsite structure 43, such as a platform, a rig, and/or a derrick positioned over the wellbore 14, and a bottom hole assembly (BHA) 44 suspended from the wellsite structure 43 into the wellbore 14 via a drill string 45. The BHA 44 includes a drill bit 46, a steering module 48 for manipulating orientation of the drill bit 46, the sampling tool 12, and one or more data collection module 50, 52. For example, the data collection modules 50, 52 may include a measurement-while-drilling (MWD) module 50 and a logging-while-drilling (LWD) module 52. The MWD module 50 may be operable for collecting information related to the formation 15 and the downhole fluid within the wellbore 14. The MWD module 50 may be operable to collect the information in real-time during drilling operations. The LWD module 52 may be operable for collecting information related to characteristics of the BHA 44 and the wellbore 14, such as orientation (e.g., azimuth and inclination) of the drill bit 46, torque, shock and vibration, weight on the drill bit 46, and downhole temperature and pressure. Additionally, although the wellsite systems 10, 42 are depicted employed in association with an onshore wellbore 14, it is to be understood that the wellsite systems 10, 42 may also be employed offshore.

FIGS. 3 and 4 are schematic views of a portion of an example implementation of the sampling module 12 shown in FIGS. 1 and 2 according to one or more aspects of the present disclosure. Namely, the figures show an example pump assembly 25 forming the pump-out module 24 shown in FIG. 1 and described above. The pump-out module 24 may be utilized to: draw the downhole fluid from the wellbore 14 or the formation 15 and into the flow line 36 via the probe module 20; pump the downhole fluid into one or more sample chambers within the fluid sample module 28; or dispose of the downhole fluid by pumping the downhole fluid through the flow line 36 into the wellbore 14 through the outlet 38. In other words, the pump-out module 24 may be utilized for pumping the downhole fluid into, though, and out of the sampling tool 12. For clarity, the downhole fluid drawn into and through the sampling tool 12 via the probe module 20 and the flow line 36, respectively, will be referred to hereinafter as the “fluid.”

In the illustrated implementation, the pump assembly 25 includes a positive displacement, two-stroke piston pump, referred to herein as a displacement unit 54. The displacement unit 54 may be energized by the fluid discharged by a first pump 56 and/or a second pump 58. A hydraulic circuit 96 (e.g., a plurality of flow lines) provides the fluid from the first and second pumps 56, 58 to energize the displacement unit 54. The displacement unit 54 comprises a first cylinder 60 and a second cylinder 62. The first cylinder 60 is formed between a first end wall 64 and a second end wall 66, while the second cylinder 62 is formed between a first end wall 68 and a second end wall 70. The displacement unit 54 further comprises a piston 72, which includes a first piston head 74 disposed within the first cylinder 60 and a second piston head 76 disposed within the second cylinder 62. A first chamber 78 is formed between the first piston head 74 and the second end wall 66 and a second chamber 80 is formed between the second piston head 76 and the first end wall 68. The first piston head 74 may be connected with or carry a first detectable feature, such as a first magnet 82, while the second piston head 76 may be connected with or carry a second detectable feature, such as a second magnet 83.

The piston 72 is movable within the displacement unit 54 between a first end of the stroke position, shown in FIG. 4, in which the first and second piston heads 74, 76 are proximate the first end walls 64, 68, respectively, and a second end of the stroke position, in which the first and second piston heads 74, 76 are proximate the second end walls 66, 70, respectively. As shown in FIG. 3, the piston 72 is movable in a first stroke direction, indicated by arrow 73, from the first end of the stroke position toward the second end of the stroke position. As shown in FIG. 4, the piston 72 is also movable in a second stroke direction, indicated by arrow 75, from the second end of the stroke position toward the first end of the stroke position. The piston 72 may complete a full stroke when the piston 72 travels a distance that is substantially equal to the distance between the first end wall 64 and the second end wall 66 or between the first end wall 68 and the second end wall 70. Each pump cycle may comprise two consecutive full strokes of the piston 72.

As further shown in FIGS. 3 and 4, the pump assembly 25 comprises a plurality of fluid flow lines and flow control valves operable to control the movement of the piston 72 during each pump cycle according to one or more aspects of the present disclosure. The pump assembly 25 includes a first flow line 84 having a pair of flow control valves CV1, CV2 for selectively communicating the fluid to or from the displacement unit 54 and a second flow line 86 connected with a pair of flow control valves CV3, CV4 for selectively communicating the fluid to or from the displacement unit 54. For example, the first flow line 84 and the flow control valves CV1, CV2 selectively communicate the fluid from the flow line 36 to the first chamber 78 of the displacement unit 54, and the second flow line 86 and the flow control valves CV3, CV4 selectively communicate the fluid from the flow line 36 to the second chamber 80 of the displacement unit 54.

The fluid is further directed by the first and/or second hydraulic pumps 56, 58 through solenoid valves SOL1, SOL2, which form part of a control system 88 for the pump assembly 25, to control the operation of the flow control valves CV1-CV4. The flow control valves CV1-CV4 may be passive valves (e.g., check valves) or active valves (e.g., remotely activated flow valves). In an active system, the flow control valves CV1-CV4 are operated between open and closed positions, for example via the control system 88 and the solenoid valves SOL1, SOL2. In a passive system, the solenoid valves SOL1, SOL2 may be utilized, for example, to shift check slides to set the bias of the flow control valves CV1-CV4. The passive system ensures that the fluid flows through the flow control valves CV1-CV2 when the stroke directions 73, 75 of the piston 72 reverse. A sufficient fluid-flowing pressure may be maintained in flow lines 84, 86 to overcome the biasing force of the respective passive flow control valves CV1-CV4. Solenoid valve SOL3 and an associated poppet valve network 90 or other hydraulic circuitry may be provided to reciprocate the piston 72 of the displacement unit 54.

The control system 88 may further include one or more sensors 92 to detect the position of the piston 72. The one or more sensors 92 may include a Hall Effect sensor, a giant magnetoresistance (GMR) sensor, or another sensor that may detect the magnetic field produced by the magnets 82, 83. The control system 88 may also include system electronics 94 that automatically command the solenoid valves SOL1-SOL3 to selectively deliver the fluid via one or both of the first and second hydraulic pumps 56, 58 to achieve the proper settings for the flow control valves CV1-CV4. Thus, the control system 88 may be operable to synchronize the operation of the displacement unit 54 with the flow control valves CV1-CV4, such that each flow control valve CV1-CV4 is caused to open or close (e.g., in the active system) or is biased for flow in a predetermined direction (e.g., in the passive system) at or near the time that the piston 72 completes each of its two strokes.

Continuously or frequently monitoring the position of the piston 72 within the displacement unit 54 via the sensor 92 and the system electronics 94 may improve performance of the displacement unit 54. For example, monitoring the position of the piston 72 may cause a “dead volume” within the chambers 78, 80 to be minimized without the risks associated with high force impacts between the piston heads 74, 76 and the end walls 64, 66, 68, 70. Additionally, monitoring the position of the piston 72 may help facilitate smooth and controlled transitions between the first stroke direction 73 and the second stroke direction 75, thereby permitting shorter interruptions in fluid flow. Furthermore, knowing the position of the piston 72 may help facilitate more accurate monitoring of the fluid flow and volume rates of the fluid within the pump assembly 25. Also, the pump assembly 25 may monitor the position of the piston 72 via the sensor 92 and the system electronics 94 to help determine when the piston 72 is nearing an end of the stroke position. When the sensor 92 detects that the piston 72 is nearing an end of the stroke position, the system electronics 94 may actuate the solenoid valve SOL3 and one or both of the first and second pumps 56, 58 to smoothly reverse the stroke direction of piston 72, while maximizing the stroke length, preventing high force impacts, and minimizing the dead volume.

Accordingly, FIGS. 1-4 and the corresponding text provide a number of different components and mechanisms for pumping wellbore and/or formation fluids into, out of, and through a device, such as the sampling tool 12. The foregoing also provides components and mechanisms for monitoring and controlling the operation of the pump assembly 25, including the displacement unit 54. In order to accurately control the operation of the pump assembly 25, the pump assembly 25 may have to be calibrated.

Implementations of the present disclosure include methods for calibrating and/or operating a pump assembly, such as the pump assembly 25. For example, FIGS. 5, 9, and 10 illustrate flow-chart diagrams of at least a portion of example implementations of methods (100), (110), (130) for calibrating and operating the pump assembly 25 according to one or more aspects of the present disclosure. While the methods (100), (110), (130) shown in FIGS. 5, 9, and 10 are described below with reference to the components and diagrams of FIGS. 1-4, it is to be understood that the methods may be performed without the components of FIGS. 1-4 or with other components. Additionally, it is to be understood that although each method is described as having a particular order, portions of the methods may be performed simultaneously or in other orders. It is also to be understood that some aspects of the described methods may not be utilized in each implementation of the present disclosure.

FIG. 5 shows the method (100) for calibrating the pump assembly 25, which comprises the displacement unit 54 and one or more pumps 56, 58 that activate the displacement unit 54. The method 100 comprises characterizing (102) the one or more pumps 56, 58 to determine one or more performance characteristics of the one or more pumps 56, 58. The one or more performance characteristics determined during the characterization (102) of the one or more pumps 56, 58 may include volumetric efficiency of each of the one or more pumps 56, 58 or a combined pump volumetric efficiency of the one or more pumps 56, 58. Thus, for example, characterizing (102) the one or more pumps may include individually characterizing the first pump 56 of the one or more pumps 56, 58 and characterizing the second pump 58 of the one or more pumps 56, 58. In other implementations, characterizing (102) the one or more pumps 56, 58 may include characterizing the first and second pumps 56, 58 of the one or more pumps 56, 58 together.

Characterizing (102) the one or more pumps 56, 58 to determine the one or more performance characteristics of the one or more pumps 56, 58 may include one or more aspects. For example, characterizing (102) the one or more pumps 56, 58 may include operating the one or more pumps 56, 58 under a plurality of predefined operating conditions. Characterizing (102) the one or more pumps 56, 58 may also include determining the one or more performance characteristics of the one or more pumps 56, 58 based on operation of the one or more pumps 56, 58 under each of the plurality of predefined operating conditions. Furthermore, characterizing the one or more pumps 56, 58 may include generating one or more data curves of the one or more performance characteristics of the one or more pumps 56, 58 for each of the plurality of predefined operating conditions.

The plurality of predefined operating conditions at which the one or more pumps 56, 58 are operated during the characterization (102) process may include at least two fluid viscosities, at least two operating pressures, and/or at least two operating speeds. Operating the one or more pumps 56, 58 under various predefined operating conditions provides data about how the one or more pumps 56, 58 perform under the various predefined operating conditions. Such data, alone or in combination with other data, may be utilized when the one or more pumps 56, 58 are operated in actual operating conditions (e.g., in the wellbore 14) to determine the operation characteristics or performance of the pump assembly 25. For example, the data may be utilized to estimate fluid flow rates and volume levels. The data may also be utilized to adjust flow rate estimates based on the actual operating conditions (e.g., downhole conditions), such as actual pressure, speed, and viscosity. Furthermore, the data may be utilized to determine error estimations for the fluid flow rates as a result of pressure and speed variations.

The method (100) may also include calibrating (104) a sensor, such as the sensor 92, associated with the displacement unit 54 under operating conditions of a first environment. Calibrating (104) the sensor 92 is also referred to herein as a first sensor calibration process (104). The first environment may be, for example, at the surface near the wellbore 14. Calibrating (104) the sensor 92 under the operating conditions of the first environment may include moving the piston 72 of the displacement unit 54 in the first stroke direction 73 until the piston 72 reaches an end of a first stroke, and moving the piston 72 in the second stroke direction 75 through a known stroke length. In some implementations, moving the piston 72 in the second stroke direction 75 through the known stroke length may include moving the piston 72 in the second stroke direction 75 until the piston 72 reaches an end of a second stroke.

As the piston 72 moves in the first stroke direction 73 until reaching the end of the first stroke, the sensor 92 detects a changing magnetic field produced by the magnets 82, 83 carried by the piston 72. When the sensor 92 detects that the magnetic field is no longer changing, it is known that the piston 72 has reached the end of the first stroke. Thereafter, the piston 72 may be moved in the second stroke direction 75. As the piston 72 moves in the second stroke direction 75, the sensor 92 again detects the changing magnetic field produced by the magnets 82, 83. As before, when the sensor 92 detects that the magnetic field is no longer changing, it is known that the piston 72 has reached the end of the second stroke. As the piston 72 moves through the first and second strokes and the sensor 92 detects the changing magnetic field, the sensor 92 generates a signal or information that may be representative of the magnetic field produced by the magnets 82, 83.

The signal produced by the sensor 92 may be correlated with the position of the piston 72 to produce a position-signal look-up table and/or a position-signal curve. In some implementations, operating parameters of the one or more pumps 56, 58 during the calibration of the sensor 92 are utilized to correlate the sensor signal with the position of the piston 72. For example, during movement of the piston 72 in the second stroke direction 75, an operating parameter of the one or more pumps 56, 58 and the signal produced by the sensor 92 may be monitored. Utilizing data collected during the characterization (102) of the one or more pumps 56, 58, the monitored operating parameter of the one or more pumps 56, 58 may be correlated to the sensor signal in order to generate the position-signal look-up table and/or the position-signal curve. FIG. 6 is a graph illustrating an example position-signal curve 105 generated from the data collected during the first sensor calibration process (104) according to one or more aspects of the present disclosure. The amplitude of the signal generated by the sensor 92 is shown along a vertical axis, which is designated as “Sensor Signal,” while the position of the piston 72 is shown along a horizontal axis, which is designated as “Position.” Furthermore, the piston position having a value of zero is associated with the first end of the stroke position described above and the piston position having a value of seven is associated with the second end of the stroke position described above.

The method (100) may also include calibrating (106) the sensor 92 associated with the displacement unit 54 under operating conditions of a second environment. Calibrating (106) the sensor 92 may also be referred to herein as a second sensor calibration process (106). The second environment may be, for example, in the wellbore 14. The process for calibrating (106) the sensor 92 under the operating conditions of the second environment may be similar or identical to the process for calibrating (104) the sensor 92 under the operating conditions of the first environment. For example, calibrating (106) the sensor 92 under the operating conditions of the second environment may include moving the piston 72 of the displacement unit 54 in the first stroke direction 73 until the piston 72 reaches an end of a first stroke, and moving the piston 72 in the second stroke direction 75 through the known stroke length. In some implementations, moving the piston 72 in the second stroke direction 75 through the known stroke length may include moving the piston 72 in the second stroke direction 75 until the piston 72 reaches an end of the second stroke.

As before, the sensor 92 detects the changing magnetic field produced by the magnets 82, 83 on the piston 72 as the piston 72 moves in the first stroke direction 73 until reaching the end of the first stroke. When the sensor 92 detects that the magnetic field is no longer changing, it is known that the piston 72 has reached the end of the first stroke. Thereafter, the piston 72 may be moved in the second stroke direction 75. As the piston 72 moves in the second stroke direction 75, the sensor 92 again detects the changing magnetic field produced by the magnets 82, 83. As before, when the sensor 92 detects that the magnetic field is no longer changing, it is known that the piston 72 has reached the end of the second stroke. As the piston 72 moves through the first and second strokes and the sensor 92 detects the changing magnetic field, the sensor 92 generates information or a signal that may be representative of the magnetic field produced by the magnets 82, 83.

As with the first sensor calibration process (104), the signal produced by the sensor 92 during the second sensor calibration process (106) may be correlated with the position of the piston 72 to produce a position-signal look-up table and/or a position-signal curve. In some implementations, the operating parameters of the one or more pumps 56, 58 during the calibration of the sensor 92 are utilized to correlate the sensor signal with the position of the piston 72. For example, during movement of the piston 72 in the second stroke direction 75, an operating parameter of the one or more pumps 56, 58 and the signal produced by the sensor 92 may be monitored. Utilizing data collected during the characterization (102) of the one or more pumps 56, 58, the monitored operating parameter of the one or more pumps 56, 58 may be correlated to the sensor signal in order to generate a position-signal look-up table and/or a position-signal curve. FIG. 7 is a graph illustrating an example position-signal curve 107 generated from the data collected during the second sensor calibration process (106) according to one or more aspects of the present disclosure. The curve 107 is shown overlaid on the position-signal curve 105 generated from the data collected during the first sensor calibration process (104).

The method (100) may also include calibrating (108) the one or more pumps 56, 58 under operating conditions of the second environment to determine one or more performance characteristics of the one or more pumps 56, 58 at the operating conditions of the second environment 108. The calibrating (108) of the one or more pumps 56, 58 is also referred to herein as the second pump calibration process (108). Such calibration (108) of the one or more pumps 56, 58 may include operating the first pump 56 of the one or more pumps 56, 58 to move the piston 72 from a first known position to a second known position. At least one of the first and second known positions may be determined from the signal produced by the sensor 92.

By way of illustration, with the piston 72 positioned at an end of the stroke (e.g., the first known position), the first pump 56 may be operated to move the piston 72 to a second position (e.g., the second known position) that may be determined from the above-described position-signal curve 107 or related look-up table. For example, as shown in FIG. 8, the piston 72 may be moved, via operation of the first pump 56, from the end of the stroke position (corresponding to the left end of the graph) to the second position indicated by line 109. The position of the piston 72, as indicated by line 109, may be determined by measuring the magnetic field produced by the magnets 82, 83 and finding a corresponding magnetic field value on the position-signal curve 107. The second pump calibration process (108) may also include monitoring operation of the first pump 56 and the time it takes to move the piston 72 from the first known position to the second known position. Thereafter, the piston 72 may be moved, via operation of the second pump, from a second known position to a first known position while monitoring the operation of the second pump 58 and the time it takes to move the piston 72 from the second known position to the first known position. Utilizing the data determined during one or more of the processes (102), (104), (106) and the data determined during the second pump calibration process (108), the operation of the one or more pumps 56, 58 may be calibrated for operation in the second environment.

FIG. 9 shows another method (110) according to one or more aspects of the present disclosure. The method (110) comprises providing (112) the sampling tool 12, which may include the pump assembly 25 having the displacement unit 54. The displacement unit 54 may include the piston 72 with the first piston head 74 positioned in the first cylinder 60, the second piston head 76 positioned in the second cylinder 62, and the sensor 92 that detects the position of the piston 72. The pump assembly 25 may also include the first pump 56 that selectively activates the displacement unit 54, and the second pump 58 that selectively activates the displacement unit 54.

The method (110) may also include characterizing (114) the first and second pumps 56, 58 to determine performance characteristics of the first and second pumps 56, 58 under a plurality of predefined operating conditions. Characterizing (114) the first and second pumps 56, 58 may be performed in a manner that is similar or identical to that described above in connection with the initial pump calibration process (102) of the method (100).

The method (110) may also include calibrating (116) the sensor 92 prior to positioning the sampling tool 12 in the wellbore 14 and calibrating (118) the sensor 92 while the sampling tool 12 is positioned in the wellbore 14. The calibration (116) of the sensor 92 is also referred to herein as calibrating the sensor uphole (116) and the calibration (118) is also referred to herein as calibrating the sensor downhole (118). The processes for calibrating the sensor uphole (116) may be similar or identical to the first sensor calibration process (104), as described above in connection with the method (100).

For example, calibrating (116) the sensor 92 prior to positioning the sampling tool 12 in the wellbore 14 may include moving the piston 72 from a first known position, through a full stroke length, to a second known position, and monitoring the signal produced by the sensor 92 during movement of the piston 72 through the full stroke length. Likewise, the processes for calibrating the sensor downhole (118) may be similar or identical to the second sensor calibration process (106) described above in connection with the method (100). For example, calibrating (118) the sensor 92 while the sampling tool 12 is positioned in the wellbore 14 may include moving the piston 72 from the first known position, through the full stroke length, to the second known position, and monitoring the signal produced by the sensor 92 during movement of the piston 72 through the full stroke length.

The method (110) may also include calibrating (120) the second pump 58 while the sampling tool 12 is positioned in the wellbore 14. The process for calibrating the second pump 58 while the sampling tool 12 is positioned in the wellbore 14 may be similar or identical to the second pump calibration process (108) described above in connection with the method (100). For example, calibrating (120) the second pump 58 while the sampling tool 12 is positioned in the wellbore 14 may include operating the first and second pumps 56, 58 to move the piston 72 to a known intermediate position determined by the signal produced by the sensor 92, and operating the second pump 58 to move the piston 72 from the know intermediate position to an end of the stroke position.

FIG. 10 shows another method (130) according to one or more aspects of the present disclosure. The method (130) comprises providing (132) the pump assembly 25 with the displacement unit 54. The displacement unit 54 may comprise the piston 72 having the first piston head 74 positioned in the first cylinder 60, the second piston head 76 positioned in the second cylinder 62, and the sensor 92. The pump assembly 25 may also include the first pump 56 that selectively activates the displacement unit 54 and the second pump 58 that selectively activates the displacement unit 25.

The method (130) may also include monitoring (134) the signal produced by the sensor 92. Utilizing the signal produced by the sensor 92, the method (130) may include determining (136) the position of the piston 72. Additionally, the method (130) may include calibrating (138) at least one of the first and second pumps 56, 58 utilizing the position of the piston 72. The process for calibrating (138) at least one of the first and second pumps 56, 58 utilizing the position of the piston 72 may include operating one of the first and second pumps 56, 58 to move the piston 72 from a first known position to a second known position. At least one of the first and second known positions may be determined from the signal produced by the sensor 92. The process for calibrating (138) at least one of the first and second pumps 56, 58 may also include monitoring the time it takes to move the piston 72 from the first known position to the second known position.

In some implementations, the method (130) may also include characterizing the first and second pumps 56, 58 to determine performance characteristics of the first and second pumps 56, 58 under a plurality of predefined operating conditions. The characterization of the first and second pumps 56, 58 may be performed prior to the monitoring (134) of the sensor signal. As discussed above, the characterization of the first and second pumps 56, 58 may be performed individually or in combination. Furthermore, the characterization of the first and second pumps 56, 58 may include operating one or both of the first and second pumps 56, 58 at various fluid viscosities, operating pressures, and/or operating speeds.

The ability and effectiveness of utilizing magnetic field sensors, such as the sensor 92, to monitor the position of the piston 72 as the piston 72 moves within the displacement unit 54 may depend on location, orientation, and quantity of the magnetic field sensors with respect to the magnets 82, 83 and, thus, the piston 72.

FIG. 11 is a schematic view of a portion of another example implementation of the pump assembly 25 shown in FIG. 3 according to one or more aspects of the present disclosure, and designated in FIG. 11 by reference number 27. The pump assembly 27 depicted in FIG. 11 is substantially similar in structure and operation to the pump assembly 25 depicted in FIG. 3, including where indicated by like reference numbers, except as described below. The following description refers to FIGS. 3 and 11, collectively.

Each magnet 82, 83 comprises a north pole N and a south pole S, and produces a magnetic field, as depicted by example magnetic field lines 152 extending from the north pole N to the south pole S. For clarity, FIG. 11 shows the magnetic field lines 152 of the magnetic field generated by the first magnet 82, but not for the second magnet 83. However, it is to be understood that each magnet 82, 83 generates a magnetic field extending around each magnet 82, 83, even if not depicted in the figures.

The magnetic poles of the magnets 82, 83 are depicted in FIG. 11 as being oriented in the same direction, such that each magnet 82, 83 has a north pole N facing a direction towards the first cylinder 60 and a south pole S facing an opposite direction towards the second cylinder 62. For the sake of simplicity, such orientation will be referred to hereinafter as NS-NS. By this convention, if each magnet 82, 83 has a south pole S facing the direction towards the first cylinder 60 and a north pole N facing the direction towards the second cylinder 62, the orientation is referred to as SN-SN. The magnetic poles of the magnets 82, 83 may also be oriented with opposing polarities. Thus, in an NS-SN orientation, the magnet 82 has a north pole N facing the direction towards the first cylinder 60 and a south pole S facing the direction towards the second cylinder 62, and the magnet 83 has a south pole S facing the direction towards the first cylinder 60 and a north pole N facing the direction towards the second cylinder 62. Similarly, in an SN-NS orientation, the magnet 82 has a south pole S facing the direction towards the first cylinder 60 and a north pole N facing the direction towards the second cylinder 62, and the magnet 83 has a north pole N facing the direction towards the first cylinder 60 and a south pole S facing the direction towards the second cylinder 62. Each such arrangement is within the scope of the present disclosure.

Instead of the sensor 92 described above, the pump assembly 27 includes a sensor 95 operable to measure the strength of the magnetic fields of the magnets 82, 83 and generate corresponding information or signals. For example, the sensor 95 may generate a signal that is proportional in amplitude to, or otherwise indicative of, the strength of the magnetic fields of each of the magnets 82, 83. As described above, the piston 72 moves in the first and second stroke directions 73, 75 along the longitudinal axis 150 of the piston 72. Accordingly, when the piston 72 moves in the first and second stroke directions 73, 75, the magnetic field strengths of the magnets 82, 83 at the location of the sensor 95 change, and the amplitude and/or other characteristic of the sensor signal correspondingly changes.

The sensor 95 may be disposed in a region 61 generally interposing the first and second cylinders 60, 62. The sensor 95 comprises an axis of magnetic field sensitivity, which is referred to hereinafter as a measurement direction. The sensor 95 may be oriented such that the measurement direction is substantially parallel to the longitudinal axis 150 of the piston 72, as depicted in FIG. 11 by a measurement direction 154. However, the sensor 95 may instead be oriented such that the measurement direction is substantially perpendicular to the longitudinal axis 150 of the piston 72, as depicted in FIG. 11 by a measurement direction 156.

As described above, the piston 72 moves through a stroke between a first end, in which the first piston head 74 is adjacent or proximate the first end wall 64 of the first cylinder 60, and a second end, in which the second piston head 76 is adjacent or proximate the second end wall 70 of the second cylinder 62. The sensor 95 is operable to measure the magnetic field strength of the magnet 82 as the piston 72 moves through the stroke, or at least a portion of the stroke. The sensor 95 is also operable to measure the magnetic field strength of the magnet 83 as the piston 72 moves through the stroke, or at least a portion of the stroke. For example, the sensor 95 may operable to measure the magnetic field strength of the first magnet 82 as the piston 72 moves through a first portion of the stroke, and to measure the magnetic field strength of the second magnet 83 as the piston 72 moves through a second portion of the stroke. The first portion of the stroke may extend between the first end of the stroke and at least a midpoint of the stroke, and the second portion of the stroke may extend between the second end of the stroke and at least the midpoint of the stroke. The first and second portions of the stroke may at least partially overlap. However, the sensor 95 may also be operable to measure the magnetic field strength of one or both of the magnets 82, 83 as the piston 72 moves through the entire stroke.

The signal or information generated by the sensor 95 as the piston 72 moves in the first and second stroke directions 73, 75 may be correlated with the position of the piston 72 within a stroke. For example, the correlation information may be utilized to produce a position-signal look-up table and/or a position-signal curve. Accordingly, during pumping and/or sampling operations of the sampling tool 12, the system electronics 94 or other portion of the control system 88 may cause the hydraulic circuitry 96, the pumps 56, 58, and/or the poppet valve network and SOL3 90 to control the displacement unit 54 based at least partially on the information generated by the sensor 95.

For example, the control system 88 may cause the hydraulic circuitry 96, the pumps 56, 58, and/or the poppet valve network and SOL3 90 to control the motion of the piston 72 based on determination by the control system 88 that the piston 72 has reached or is nearing an end of the stroke, where such determination may be at least partially based on the information generated by the sensor 95. The control system 88 may also or instead cause the hydraulic circuitry 96, the pumps 56, 58, and/or the poppet valve network and SOL3 90 to control the motion of the piston 72 based on determination of the position of the piston 72 substantially continuously throughout the stroke, where such determination may be at least partially based on the information generated by the sensor 95. For example, the control system 88 may cause the hydraulic circuitry 96, the pumps 56, 58, and/or the poppet valve network and SOL3 90 to reverse the direction or change the speed of travel of the piston 72 based on the information generated by the sensor 95.

The signal or information generated by the sensor 95 is affected by the relative orientation and position of the magnets 82, 83 and the sensor 95. For example, the signal generated by the sensor 95 is dependent upon the orientation or direction of the magnetic poles of the magnets 82, 83 with respect to the sensor 95, and is also dependent upon the orientation of the measurement direction 154, 156 of the sensor 95. Implementations within the scope of the present disclosure include those in which the magnets 82, 83 have either of the NS-NS, SN-SN, NS-SN, or SN-NS orientations described above. In each such implementation, the sensor 92 may have the measurement direction 154 or the measurement direction 156.

FIG. 12 is a schematic view of a portion of another example implementation of the pump assembly 27 shown in FIG. 11 according to one or more aspects of the present disclosure, and designated in FIG. 12 by reference number 29. The pump assembly 29 depicted in FIG. 12 is substantially similar in structure and operation to the pump assembly 25 depicted in FIG. 3 and the pump assembly 27 depicted in FIG. 11, including where indicated by like reference numbers, except as described below. The following description refers to FIGS. 3, 11, and 12, collectively.

Instead of the sensor 95 shown in FIG. 11, the pump assembly 29 depicted in FIG. 12 comprises a first sensor 91 and a second sensor 93. The first sensor 91 is disposed in substantial alignment with or otherwise proximate the first end wall 64 of the first cylinder 60, and the second sensor 93 is disposed in substantially alignment with or otherwise proximate the second end wall 70 of the second cylinder 62. Each of the sensors 91, 93 comprises the same or similar structure and/or function as the sensor 95 described above.

The first sensor 91 is operable to measure the magnetic field strength of the first magnet 82 as the piston 72 moves through the first portion of the stroke described above. The second sensor 93 is operable to measure the magnetic field strength of the second magnet 83 as the piston 72 moves through the second portion of the stroke described above. However, the first sensor 91 may be operable to measure the magnetic field strength of the first magnet 82 as the piston 72 moves through the entire piston stroke, and/or the second sensor 93 may be operable to measure the magnetic field strength of the second magnet 83 as the piston 72 moves through the entire piston stroke. In a manner similar to as described above with respect to the sensor 95, the signals or information generated by the sensors 91, 93 as the piston 72 moves in the first and second stroke directions 73, 75 may be correlated with the position of the piston 72 to produce a position-signal look-up table and/or a position-signal curve.

The magnets 82, 83 of the pump assembly 29 may have a NS-NS, SN-SN, NS-SN, or SN-NS orientation. The sensors 91, 93 may each have the measurement direction 154, or may each have the measurement direction 156. However, one of the sensors 91, 93 may have the measurement direction 154, while the other one of the sensors 91, 93 may have the measurement direction 156.

FIG. 13 is a schematic view of a portion of another example implementation of the pump assembly 29 shown in FIG. 12 according to one or more aspects of the present disclosure, and designated in FIG. 13 by reference number 31. The pump assembly 31 depicted in FIG. 13 is substantially similar in structure and operation to the pump assembly 25 depicted in FIG. 3, the pump assembly 27 depicted in FIG. 11, and the pump assembly 29 depicted in FIG. 12, including where indicated by like reference numbers, except as described below. The following description refers to FIGS. 3 and 11-13, collectively.

The pump assembly 31 depicted in FIG. 13 differs from the pump assembly 29 depicted in FIG. 12 in that the sensor 91 is disposed in substantial alignment with the longitudinal axis 150 of the piston 72, or otherwise adjacent or proximate a longitudinal end of the displacement unit 55 instead of a side of the displacement unit 55. Although not depicted as such in FIG. 13, the sensor 93 may similarly be disposed adjacent or proximate the other longitudinal end of the displacement unit 55, whether instead of or in addition to such disposition of the sensor 91.

The pump assembly 31 depicted in FIG. 13 also differs from the pump assembly 29 depicted in FIG. 12 (and others) in that the pump assembly 31 comprises a displacement unit 55 that is substantially similar to the displacement unit 54 described above except that the displacement unit 55 does not comprise the second magnet 83. Although the displacement unit 55 is depicted as comprising the first magnet 82 carried with the first piston head 74 but not the second magnet 83 carried with the second piston head 76, it is to be understood that the displacement unit 55 may instead comprise the second magnet 83 carried with the second piston head 76 but not the first magnet 82 carried with the first piston head 74.

The first sensor 91 is operable to measure the magnetic field strength of the first magnet 82 as the piston 72 moves through the first portion of the stroke described above, and the second sensor 93 is operable to measure the magnetic field strength of the first magnet 82 as the piston 72 moves through the second portion of the stroke described above. However, one or both of the sensors 91, 93 may be operable to measure the magnetic field strength of the first magnet 82 as the piston 72 moves through the entire piston stroke.

In a manner similar to as described above, the signals or information generated by the sensors 91, 93 as the piston 72 moves in the first and second stroke directions 73, 75 may be correlated with the position of the piston 72 to produce a position-signal look-up table and/or a position-signal curve. The magnet 82 of the pump assembly 31 may have a NS or SN orientation. The sensors 91, 93 may each have the measurement direction 154, or may each have the measurement direction 156. However, one of the sensors 91, 93 may have the measurement direction 154, while the other one of the sensors 91, 93 may have the measurement direction 156.

FIGS. 14-17 are graphs showing example position-signal curves generated from the sensor signal collected during the calibration process of the pump assembly 27 according to one or more aspects of the present disclosure. In each graph, the amplitude of the signal generated by the sensor 95 is shown along the vertical axis, which is designated as “Sensor Signal,” while the position of the piston 72 is shown along the horizontal axis, which is designated as “Position.” The piston position is between the first and second ends of the stroke described above. The following description of FIGS. 14-17 also refers to FIG. 11. However, one or more aspects described below are also applicable or readily adaptable to the pump assembly 29 depicted in FIG. 12, the pump assembly 31 depicted in FIG. 13, and/or other pump assemblies within the scope of the present disclosure.

FIG. 14 shows a curve 160 based on the signal or information generated by the sensor 95, relative to position of the piston 72 within the stroke, for an implementation in which the sensor 95 has the measurement direction 154 and the magnets 82, 83 are in the NS-NS orientation. The curve 160 is positive over the entire travel of the piston 72, comprises gradients 161 near the ends of the stroke, and is substantially flat near the midpoint of the stroke. The curve 160 indicates a maximum measured strength 162 of the magnetic field of the first magnet 82 at the first end of the stroke, and a minimum measured strength 164 of the magnetic field of the first magnet 82 proximate the midpoint of the stroke. The curve 160 also indicates a maximum measured strength 166 of the magnetic field of the second magnet 83 at the second end of the stroke, and a minimum measured strength 168 of the magnetic field of the second magnet 83 proximate the midpoint of the stroke.

FIG. 15 shows a curve 170 based on the signal or information generated by the sensor 95, relative to position of the piston 72 within the stroke, for an implementation in which the sensor 95 has the measurement direction 156 and the magnets 82, 83 are in the NS-NS orientation. The curve 170 is positive over the first portion of the piston stroke and negative over the second portion of the piston stroke. The curve 170 indicates a maximum positive value 172 of the measured strength of the magnetic field of the first magnet 82 proximate (but not at) the first end of the stroke, and a minimum positive value 174 of the measured strength of the magnetic field of the first magnet 82 proximate the midpoint of the stroke. The curve 170 also indicates a maximum negative value 176 of the measured strength of the magnetic field of the second magnet 83 proximate (but not at) the second end of the stroke, and a minimum negative value 178 of the measured strength of the magnetic field of the second magnet 83 proximate the midpoint of the stroke. Thus, the curve 170 demonstrates that the sensor 95 may output a signal having the same amplitude (although of opposite sign) at two different piston positions. The curve 170 also exhibits notable slope substantially continuously between the maximum positive value 172 and the maximum negative value 176, and gradients 171 between the ends of the stroke and the corresponding maximum positive and negative values 172, 176.

FIG. 16 shows a curve 180 based on the signal or information generated by the sensor 95, relative to position of the piston 72 within the stroke, for an implementation in which the sensor 95 has the measurement direction 154 and the magnets 82, 83 are in the NS-SN orientation. The curve 180 is positive over the first portion of the piston stroke and negative over the second portion of the piston stroke. The curve 180 indicates a maximum positive value 182 of the measured strength of the magnetic field of the first magnet 82 proximate (but not at) the first end of the stroke, and a minimum positive value 184 of the measured strength of the magnetic field of the first magnet 82 proximate the midpoint of the stroke. The curve 180 also indicates a maximum negative value 186 of the measured strength of the magnetic field of the second magnet 83 proximate (but not at) the second end of the stroke, and a minimum negative value 188 of the measured strength of the magnetic field of the second magnet 83 proximate the midpoint of the stroke. The curve 180 also exhibits notable slope substantially continuously between the maximum positive value 182 and the maximum negative value 186, and gradients 181 between the ends of the stroke and the corresponding maximum positive and negative values 182, 186.

FIG. 17 shows a curve 190 based on the signal or information generated by the sensor 95, relative to position of the piston 72 within the stroke, for an implementation in which the sensor 95 has the measurement direction 156 and the magnets 82, 83 are in the NS-SN orientation. The curve 190 is positive over the entire travel of the piston 72, comprises gradients 191 near the ends of the stroke, and is substantially flat near the midpoint of the stroke. The curve 190 indicates a maximum measured strength 192 of the magnetic field of the first magnet 82 at the first end of the stroke, and a minimum measured strength 194 of the magnetic field of the first magnet 82 proximate the midpoint of the stroke. The curve 190 also indicates a maximum measured strength 196 of the magnetic field of the second magnet 83 at the second end of the stroke, and a minimum measured strength 198 of the magnetic field of the second magnet 83 proximate the midpoint of the stroke.

Data such as that represented by the curves 160, 170, 180, 190 shown in FIGS. 14-17 may have various utilities during operation of the pump assembly 27 and others within the scope of the present disclosure. For example, the data may be utilized to detect the position of the piston 72 at the stroke ends. Such stroke-end detection may aid in reducing dead volume between the piston heads 74, 76 and the corresponding cylinder end walls 64, 70, which may improve sample cleanup performance and/or reduce cleanup time.

The data may also be utilized to detect the position of the piston 72 as the piston heads 74, 76 approach the stroke ends. Such stroke-end-approach detection may aid in reducing turnaround time, thus minimizing interruptions of fluid flow from the formation, and thereby reducing cleanup time. Stroke-end-approach detection may also aid in reducing or preventing mechanical system shock, such as may result if the piston heads 75, 76 hit the corresponding cylinder end wall 64, 70.

The data may also be utilized to detect the position of the piston 72 substantially continuously along at least a substantial portion of the length of a stroke. Such substantially-continuous-position detection may be utilized for real-time flow rate measurement and/or control for at least a portion of the stroke, including implementations in which such measurement and/or control may consequently be adjusted in a substantially instantaneous and/or real-time manner when the piston 72 is within the range of the stroke that the substantially-continuous-position detection is performed. The substantially-continuous-position detection may also be utilized to more accurately perform small volume measurement, including in implementations in which such measurement may be utilized for formation pressure testing utilizing the pump assembly 27.

The data may also be utilized to detect the position of the piston 72 substantially continuously along the entire length of a stroke. Such detection may be utilized for real-time flow rate measurement and/or control over the entire length of the stroke, instead of utilizing an average of flow rate for the stroke.

The different polarity arrangements of the magnets 82, 83 and measurement directions 154, 156 of the sensor 95 described above provides different options for presenting the stroke position data that may be utilized as described above. However, in at least some applications, the NS-SN orientation of the magnets 82, 83 and measurement direction 156, as depicted by the curve 190 in FIG. 17, may be more a utile implementation. For example, such implementation may provide a high level of signal output, which may provide greater accuracy relative to the implementations represented by the curves 160, 170, 180 shown in FIGS. 14-16. The curve 190 also provides one-to-one matching of piston position and signal toward the ends of stroke, whereas the curves 170, 180 shown in FIGS. 15 and 16 may exhibit substantially identical magnetic field strength (or sensor signal) for two or more different piston positions. For example, the curve 170 shown in FIG. 15 includes the same sensor signal values 173 and two different piston positions 175, 177. The curve 190 also exhibits sensor signal values that are below saturation level over the entire stroke, thus maintaining high-slope gradients 191 at the stroke ends. The gradients 191 are also higher than the gradients 161, 171, 181 of the other curves 160, 170, 180, thus providing more accuracy for the stroke-end detection described above, which corresponds to the least amount of dead volume between the piston heads 74, 76 and the corresponding cylinder end walls 64, 70. The higher gradients 191 also provide greater accuracy for the stroke-end-approach detection described above, thus providing better advanced warning for piston turnaround, and thereby reducing turnaround time and formation fluid flow interruptions. The curve 190 also has better measurement capability and accuracy around both stroke ends, relative to the other curves 160, 170, 180, thus permitting greater control and accuracy for volume measurement during formation pressure testing, yet also permits adequate flow rate measurement and control during an acceptable portion of the length of the stroke.

In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising: a sampling tool for conveyance within a well that extends into a subterranean formation, wherein the sampling tool comprises: a displacement unit comprising: a first cylinder; a second cylinder; a piston comprising a first head disposed in the first cylinder and a second head disposed in the second cylinder, wherein a stroke of the piston moves the first and second heads between first positions each proximate first end walls of the respective first and second cylinders and second positions each proximate second end walls of the respective first and second cylinders; a first magnet carried with the first head; and a second magnet carried with the second head. The sampling tool also comprises a single magnetic field sensor operable to: measure a first magnetic field strength of the first magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and measure a second magnetic field strength of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke.

The single magnetic field sensor may be disposed in a region generally interposing the first and second cylinders.

The first and second magnets may be relatively oriented with same magnetic polarities, and the single magnetic field sensor may be operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel or substantially perpendicular to a longitudinal axis of the piston.

The first and second magnets may be relatively oriented with opposite magnetic polarities, and the single magnetic field sensor may be operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel or substantially perpendicular to a longitudinal axis of the piston.

The sampling tool may further comprise: a hydraulic fluid pump; hydraulic circuitry operatively connecting the hydraulic fluid pump to the first and second cylinders; and system electronics operable to control the hydraulic circuitry based at least on information received from the single magnetic field sensor.

The present disclosure also introduces an apparatus comprising: a sampling tool for conveyance within a well that extends into a subterranean formation, wherein the sampling tool comprises: a displacement unit comprising: a first cylinder; a second cylinder; a piston comprising a first head disposed in the first cylinder and a second head disposed in the second cylinder, wherein a stroke of the piston moves the first and second heads between first positions each proximate first end walls of the respective first and second cylinders and second positions each proximate second end walls of the respective first and second cylinders; and at least one magnet carried with at least one of the first and second heads; and at least one magnetic field sensor operable to measure a magnetic field strength of the at least one magnet throughout the stroke.

The at least one magnet may be a first magnet carried with the first head and a second magnet carried with the second head, and the at least one magnetic field sensor may be a single magnetic field sensor operable to: measure a first magnetic field strength of the first magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and measure a second magnetic field strength of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke. The single magnetic field sensor may be disposed in a region generally interposing the first and second cylinders. The first and second magnets may be relatively oriented with the same magnetic polarities, and the single magnetic field sensor may be operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel or substantially perpendicular to a longitudinal axis of the piston. The first and second magnets may be relatively oriented with opposite magnetic polarities, and the single magnetic field sensor may be operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel or substantially perpendicular to a longitudinal axis of the piston.

The at least one magnet may be either but not both of a first magnet carried with the first head and a second magnet carried with the second head, and the at least one magnetic field sensor may be a first magnetic field sensor and a second magnetic field sensor, wherein the first magnetic field sensor may be operable to measure a magnetic field strength of the at least one magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke, and wherein the second magnetic field sensor may be operable to measure the magnetic field strength of the at least one magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke. In such implementations, the first magnetic field sensor may be disposed proximate the first end wall of the first cylinder, and the second magnetic field sensor may be disposed proximate the second end wall of the second cylinder.

The at least one magnet may be a first magnet carried with the first head and a second magnet carried with the second head, and the at least one magnetic field sensor may be a first magnetic field sensor and a second magnetic field sensor, wherein the first magnetic field sensor may be operable to measure a first magnetic field strength of the first magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke, and wherein the second magnetic field sensor may be operable to measure a second magnetic field strength of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke. In such implementations, the first magnetic field sensor may be disposed proximate the first end of the first cylinder, and the second magnetic field sensor may be disposed proximate the second end of the second cylinder.

The sampling tool may further comprise: a hydraulic fluid pump; hydraulic circuitry operatively connecting the hydraulic fluid pump to the first and second cylinders; and system electronics operable to control the hydraulic circuitry based at least on information received from the at least one magnetic field sensor.

The present disclosure also introduces a method comprising: conveying a sampling tool within a well that extends into a subterranean formation, wherein the sampling tool comprises: a hydraulically actuated displacement unit comprising a piston and first and second magnets carried with and disposed proximate opposing ends of the piston; and a magnetic field sensor operable to substantially continuously generate: first information related to a first magnetic field of the first magnet as the piston moves through a first portion of a stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and second information related to a second magnetic field of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke; and operating the sampling tool to draw formation fluid from the subterranean formation into the displacement unit, wherein operating the sampling tool causes movement of the piston within the displacement unit to be controlled based on at least the first and second information.

The sampling tool may further comprise a hydraulic fluid source and hydraulic circuitry operably connecting the displacement unit to the hydraulic fluid source, and operating the sampling tool may cause the hydraulic circuitry to control the displacement unit based on at least the first and second information. Control of the displacement unit by the hydraulic circuitry may be based on determination of the piston reaching the first and second ends of the stroke based on the first and second information. Control of the displacement unit by the hydraulic circuitry may also or instead be based on determination of the piston nearing the first and second ends of the stroke based on the first and second information. Control of the displacement unit by the hydraulic circuitry may also or instead be based on determination of a position of the piston substantially continuously throughout the stroke based on the first and second information.

The first and second magnets may be relatively oriented with the same magnetic polarities, the magnetic field sensor may be operable to measure the first and second magnetic fields in a measurement direction that is substantially parallel to a longitudinal axis of the piston, the first information may include a first maximum measured strength of the first magnetic field at the first end of the stroke and a first minimum measured strength of the first magnetic field proximate the midpoint of the stroke, and the second information may include a second maximum measured strength of the second magnetic field at the second end of the stroke and a second minimum measured strength of the second magnetic field proximate the midpoint of the stroke.

The first and second magnets may be relatively oriented with the same magnetic polarities, the magnetic field sensor may be operable to measure the first and second magnetic fields in a measurement direction that is substantially perpendicular to a longitudinal axis of the piston, the first information may include a maximum positive value of the measured strength of the first magnetic field proximate but not at the first end of the stroke and a minimum positive value of the measured strength of the first magnetic field proximate the midpoint of the stroke, and the second information may include a maximum negative value of the measured strength of the second magnetic field proximate but not at the second end of the stroke and a minimum negative value of the measured strength of the second magnetic field proximate the midpoint of the stroke.

The first and second magnets may be relatively oriented with opposite magnetic polarities, the magnetic field sensor may be operable to measure the first and second magnetic fields in a measurement direction that is substantially parallel to a longitudinal axis of the piston, the first information may include a maximum positive value of the measured strength of the first magnetic field proximate but not at the first end of the stroke and a minimum positive value of the measured strength of the first magnetic field proximate the midpoint of the stroke, and the second information may include a maximum negative value of the measured strength of the second magnetic field proximate but not at the second end of the stroke and a minimum negative value of the measured strength of the second magnetic field proximate the midpoint of the stroke.

The first and second magnets may be relatively oriented with opposite magnetic polarities, the magnetic field sensor may be operable to measure the first and second magnetic fields in a measurement direction that is substantially perpendicular to a longitudinal axis of the piston, the first information may include a first maximum measured strength of the first magnetic field at the first end of the stroke and a first minimum measured strength of the first magnetic field proximate the midpoint of the stroke, and the second information may include a second maximum measured strength of the second magnetic field at the second end of the stroke and a second minimum measured strength of the second magnetic field proximate the midpoint of the stroke.

One or more specific implementations of the present disclosure have been described herein. These described implementations are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, some features of an actual implementation may not be described in the specification. It is to be understood that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it is to be understood that such a development effort might be complex and time consuming, but would be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

When introducing elements of various implementations of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it is to be understood that references to “one implementation” or “an implementation” of the present disclosure are not intended to be interpreted as excluding the existence of additional implementations that also incorporate the recited features.

The terms “approximately,” “about,” and “substantially” as utilized herein represent an amount close to the stated amount that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 10% of, within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount.

The present disclosure may be embodied in other specific forms without departing from its spirit or basic characteristics. The described implementations are to be considered in as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. 

What is claimed is:
 1. An apparatus, comprising: a sampling tool for conveyance within a well that extends into a subterranean formation, wherein the sampling tool comprises: a displacement unit comprising: a first cylinder; a second cylinder; a piston comprising a first head disposed in the first cylinder and a second head disposed in the second cylinder, wherein a stroke of the piston moves the first and second heads between first positions each proximate first end walls of the respective first and second cylinders and second positions each proximate second end walls of the respective first and second cylinders; a first magnet carried with the first head; and a second magnet carried with the second head; and a single magnetic field sensor operable to: measure a first magnetic field strength of the first magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and measure a second magnetic field strength of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke.
 2. The apparatus of claim 1 wherein the first and second magnets are relatively oriented with same magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel to a longitudinal axis of the piston.
 3. The apparatus of claim 1 wherein the first and second magnets are relatively oriented with same magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially perpendicular to a longitudinal axis of the piston.
 4. The apparatus of claim 1 wherein the first and second magnets are relatively oriented with opposite magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel to a longitudinal axis of the piston.
 5. The apparatus of claim 1 wherein the first and second magnets are relatively oriented with opposite magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially perpendicular to a longitudinal axis of the piston.
 6. The apparatus of claim 1 wherein the sampling tool further comprises: a hydraulic fluid pump; hydraulic circuitry operatively connecting the hydraulic fluid pump to the first and second cylinders; and system electronics operable to control the hydraulic circuitry based at least on information received from the single magnetic field sensor.
 7. An apparatus, comprising: a sampling tool for conveyance within a well that extends into a subterranean formation, wherein the sampling tool comprises: a displacement unit comprising: a first cylinder; a second cylinder; a piston comprising a first head disposed in the first cylinder and a second head disposed in the second cylinder, wherein a stroke of the piston moves the first and second heads between first positions each proximate first end walls of the respective first and second cylinders and second positions each proximate second end walls of the respective first and second cylinders; and at least one magnet carried with at least one of the first and second heads; and at least one magnetic field sensor operable to measure a magnetic field strength of the at least one magnet throughout the stroke.
 8. The apparatus of claim 7 wherein: the at least one magnet is: a first magnet carried with the first head; and a second magnet carried with the second head; and the at least one magnetic field sensor is a single magnetic field sensor operable to: measure a first magnetic field strength of the first magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and measure a second magnetic field strength of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke.
 9. The apparatus of claim 8 wherein the first and second magnets are relatively oriented with the same magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel to a longitudinal axis of the piston.
 10. The apparatus of claim 8 wherein the first and second magnets are relatively oriented with the same magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially perpendicular to a longitudinal axis of the piston.
 11. The apparatus of claim 8 wherein the first and second magnets are relatively oriented with opposite magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially parallel to a longitudinal axis of the piston.
 12. The apparatus of claim 8 wherein the first and second magnets are relatively oriented with opposite magnetic polarities, and wherein the single magnetic field sensor is operable to measure the first and second magnetic field strengths in a measurement direction that is substantially perpendicular to a longitudinal axis of the piston.
 13. The apparatus of claim 7 wherein: the at least one magnet is either but not both of: a first magnet carried with the first head; and a second magnet carried with the second head; and the at least one magnetic field sensor is: a first magnetic field sensor operable to measure a magnetic field strength of the at least one magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and a second magnetic field sensor operable to measure the magnetic field strength of the at least one magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke.
 14. The apparatus of claim 7 wherein: the at least one magnet is: a first magnet carried with the first head; and a second magnet carried with the second head; and the at least one magnetic field sensor is: a first magnetic field sensor operable to measure a first magnetic field strength of the first magnet as the piston moves through a first portion of the stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and a second magnetic field sensor operable to measure a second magnetic field strength of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke.
 15. The apparatus of claim 7 wherein the sampling tool further comprises: a hydraulic fluid pump; hydraulic circuitry operatively connecting the hydraulic fluid pump to the first and second cylinders; and system electronics operable to control the hydraulic circuitry based at least on information received from the at least one magnetic field sensor.
 16. A method, comprising: conveying a sampling tool within a well that extends into a subterranean formation, wherein the sampling tool comprises: a hydraulically actuated displacement unit comprising a piston and first and second magnets carried with and disposed proximate opposing ends of the piston; and a magnetic field sensor operable to substantially continuously generate: first information related to a first magnetic field of the first magnet as the piston moves through a first portion of a stroke that extends at least between a first end of the stroke and a midpoint of the stroke; and second information related to a second magnetic field of the second magnet as the piston moves through a second portion of the stroke that extends at least between a second end of the stroke and the midpoint of the stroke; and operating the sampling tool to draw formation fluid from the subterranean formation into the displacement unit, wherein operating the sampling tool causes movement of the piston within the displacement unit to be controlled based on at least the first and second information.
 17. The method of claim 16 wherein the sampling tool further comprises a hydraulic fluid source and hydraulic circuitry operably connecting the displacement unit to the hydraulic fluid source, and wherein operating the sampling tool causes the hydraulic circuitry to control the displacement unit based on at least the first and second information.
 18. The method of claim 17 wherein control of the displacement unit by the hydraulic circuitry is based on determination of the piston reaching the first and second ends of the stroke based on the first and second information.
 19. The method of claim 17 wherein control of the displacement unit by the hydraulic circuitry is based on determination of the piston nearing the first and second ends of the stroke based on the first and second information.
 20. The method of claim 17 wherein control of the displacement unit by the hydraulic circuitry is based on determination of a position of the piston substantially continuously throughout the stroke based on the first and second information. 